US8714249B1 - Wellbore servicing materials and methods of making and using same - Google Patents

Wellbore servicing materials and methods of making and using same Download PDF

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US8714249B1
US8714249B1 US13/662,055 US201213662055A US8714249B1 US 8714249 B1 US8714249 B1 US 8714249B1 US 201213662055 A US201213662055 A US 201213662055A US 8714249 B1 US8714249 B1 US 8714249B1
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acid
wellbore
poly
fluid
subterranean formation
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US20140116701A1 (en
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Tingji Tang
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Priority to CA2889138A priority patent/CA2889138C/fr
Priority to PCT/US2013/061434 priority patent/WO2014065975A1/fr
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/70—Compositions for forming crevices or fractures characterised by their form or by the form of their components, e.g. foams
    • C09K8/703—Foams
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/725—Compositions containing polymers

Definitions

  • This disclosure relates to methods of servicing a wellbore. More specifically, it relates to wellbore servicing fluids comprising degradable materials and methods of making and using same.
  • Natural resources residing in the subterranean formation may be recovered by driving resources from the formation into the wellbore using, for example, a pressure gradient that exists between the formation and the wellbore, the force of gravity, displacement of the resources from the formation using a pump or the force of another fluid injected into the well or an adjacent well.
  • the production of fluid in the formation may be increased by hydraulically fracturing the formation. That is, a viscous fracturing fluid may be pumped down the wellbore at a rate and a pressure sufficient to form fractures that extend into the formation, providing additional pathways through which the oil or gas can flow to the well.
  • fracturing fluid may again be pumped into the formation to form additional fractures therein.
  • the previously used fractures first must be plugged to prevent the loss of the fracturing fluid into the formation via those fractures.
  • Traditional fracturing operations also termed plug and perforate operations, to increase the productivity of the subterranean formation employ a perforation of the subterranean formation followed by setting of a fracturing plug with typical operation times ranging from 3-5 hours. Additionally to achieve a user and/or process desired goal, the fracturing may need to be repeated numerous times resulting in lengthy equipment stand by times. Once the process is complete the fracturing plugs are typically removed, for example by drilling out.
  • Alternative methods employ processes such as the ACESSFRAC PD service which utilizes perforation in conjunction with degradable diverting materials (e.g., BIOVERT NWB) and the resultant process provides numerous benefits in terms of reduced operation time, reduced equipment standby time, increased safety, reduced risk of premature setting of the fracturing plug, avoiding the need to drill out the plug before production and reducing the time for fluid flow back when compared to fracture plugs which set into place. While processes such as ACCESSFRAC PD provide advantages over the use of fracture plugs, one challenge in these operations is that the degradable diverting materials utilized also need to be removed prior to production. An ongoing need exists for improved compositions and methods for fracturing operations.
  • degradable diverting materials e.g., BIOVERT NWB
  • a method of servicing a wellbore in a subterranean formation comprising placing a first wellbore servicing fluid comprising a self-degrading diverter material into the wellbore wherein the self-degrading diverter materials comprises (i) a diverting material and (ii) a degradation accelerator; allowing the self-degrading diverter material to form a diverter plug at a first location in the wellbore or subterranean formation; diverting the flow of a second wellbore servicing fluid to a second location in the wellbore or subterranean formation; and removing the diverter plug, wherein the first and second wellbore servicing fluids may be the same or different.
  • a wellbore servicing fluid comprising self-degrading diverter material wherein the self-degrading diverter material comprises polylactide, sodium carbonate and a carrier fluid.
  • a method of servicing a wellbore in a subterranean formation comprising placing a wellbore servicing fluid into the subterranean formation at a first location; plugging the first location with a self-degrading diverter material comprising a diverting material and a degradation accelerator such that all or a portion of the wellbore servicing fluid is diverted to a second location in the subterranean formation; placing the wellbore servicing fluid into the subterranean formation at the second location; and allowing the self-degrading diverter material to degrade to provide a flowpath from the subterranean formation to the wellbore for recovery of resources from the subterranean formation.
  • FIGS. 1A and 1B are schematics of embodiments for use of the self-degrading diverter materials disclosed herein.
  • compositions comprising a diverting material and a degradation accelerator.
  • Compositions comprising a diverting material (DM) and a degradation accelerator (DA) are herein termed self-degrading diverter materials and designated (SDDM).
  • SDDM self-degrading diverter materials and designated
  • the DM comprises any material suitable for distribution within or into a flowpath (e.g., a subterranean flowpath within a wellbore and/or surrounding formation), for example, so as to form a pack, a bridge, a plug or a filter cake and thereby obstruct fluid movement via that flowpath.
  • the DM is configured to reduce the fluid flow via a given flowpath (i.e., reduce the fluid permeability of a point of entry for fluids into the formation) such that fluid movement is diverted (e.g., redirected) to another flowpath within the wellbore and/or surrounding formation, for example during a fracturing operation.
  • the DM is comprised of a naturally-occurring material.
  • the DM comprises a synthetic material.
  • the DM comprises a mixture of a naturally-occurring and synthetic material.
  • the DM comprises a degradable material that may undergo irreversible degradation downhole.
  • degradation refers to the separation of the material into simpler compounds that do not retain all the characteristics of the starting material.
  • the terms “degradation” or “degradable” may refer to either or both of heterogeneous degradation (or bulk erosion) and/or homogeneous degradation (or surface erosion), and/or to any stage of degradation in between these two. Not intending to be bound by theory, degradation may be a result of, inter alia, an external stimuli (e.g., heat, temperature, pH, etc.).
  • an external stimuli e.g., heat, temperature, pH, etc.
  • the term “irreversible” means that the degradable material, once degraded downhole, should not recrystallize or reconsolidate while downhole.
  • the DM comprises a degradable polymer.
  • the disclosure may refer to a polymer and/or a polymeric material. It is to be understood that the terms polymer and/or polymeric material herein are used interchangeably and are meant to each refer to compositions comprising at least one polymerized monomer in the presence or absence of other additives traditionally included in such materials.
  • degradable polymers suitable for use as the DM include, but are not limited to homopolymers, random, block, graft, star- and hyper-branched aliphatic polyesters, copolymers thereof, derivatives thereof, or combinations thereof.
  • derivative is defined herein to include any compound that is made from one or more of the diverting materials, for example, by replacing one atom in the diverting material with another atom or group of atoms, rearranging two or more atoms in the diverting material, ionizing one of the diverting materials, or creating a salt of one of the diverting materials.
  • copolymer as used herein is not limited to the combination of two polymers, but includes any combination of any number of polymers, e.g., graft polymers, terpolymers and the like.
  • the degradable polymer comprises polysaccharides; lignosulfonates; chitins; chitosans; proteins; proteinous materials; fatty alcohols; fatty esters; fatty acid salts; aliphatic polyesters; poly(lactides); poly(glycolides); poly( ⁇ -caprolactones); polyoxymethylene; polyurethanes; poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; polyvinyl polymers; acrylic-based polymers; poly(amino acids); poly(aspartic acid); poly(alkylene oxides); poly(ethylene oxides); polyphosphazenes; poly(orthoesters); poly(hydroxy ester ethers); polyether esters; polyester amides; polyamides; polyhydroxyalkanoates; polyethyleneterephthalates; polybutyleneterephthalates; polyethylenenaphthalenates, and copolymers, blends, derivatives, or combinations thereof.
  • the degradable polymer
  • the degradable polymer comprises substituted or unsubstituted lactides, glycolides, polylactic acid (PLA), polyglycolic acid (PGA), copolymers of PLA and PGA, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, or combinations thereof.
  • PLA polylactic acid
  • PGA polyglycolic acid
  • PLA polylactic acid
  • PGA polyglycolic acid
  • copolymers of PLA and PGA copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties
  • copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties or combinations thereof.
  • the degradable polymer comprises an aliphatic polyester which may be represented by the general formula of repeating units shown in Formula I:
  • n is an integer ranging from about 75 to about 10,000, alternatively from about 100 to about 500, or alternatively from about 200 to about 2000 and R comprises hydrogen, an alkyl group, an aryl group, alkylaryl groups, acetyl groups, heteroatoms, or combinations thereof.
  • the aliphatic polyester comprises poly(lactic acid) or polylactide (PLA). Because both lactic acid and lactide can achieve the same repeating unit, the general term poly(lactic acid), as used herein, refers to Formula I without any limitation as to how the polymer was formed (e.g., from lactides, lactic acid, or oligomers) and without reference to the degree of polymerization or level of plasticization.
  • poly(lactic acid) refers to Formula I without any limitation as to how the polymer was formed (e.g., from lactides, lactic acid, or oligomers) and without reference to the degree of polymerization or level of plasticization.
  • the lactide monomer may exist, generally, in one of three different forms: two stereoisomers L- and D-lactide and racemic D,L-lactide (meso-lactide).
  • the oligomers of lactic acid, and oligomers of lactide suitable for use in the present disclosure may be represented by general Formula II:
  • the molecular weight of the PLA may be less than about 5,400 g/mole, alternatively, less than about 720 g/mole, respectively.
  • the stereoisomers of lactic acid may be used individually or combined to be used in accordance with the present disclosure.
  • the degradable polymer comprises a copolymer of lactic acid.
  • a copolymer of lactic acid may be formed by copolymerizing one or more stereoisomers of lactic acid with, for example, glycolide, ⁇ -caprolactone, 1,5-dioxepan-2-one, or trimethylene carbonate, so as to obtain polymers with different physical and/or mechanical properties that are also suitable for use in the present disclosure.
  • degradable polymers suitable for use in the present disclosure are formed by blending, copolymerizing or otherwise mixing the stereoisomers of lactic acid.
  • degradable polymers suitable for use in the present disclosure are formed by blending, copolymerizing or otherwise mixing high and/or low molecular weight polylactides.
  • degradable polymers suitable for use in the present disclosure are formed by blending, copolymerizing or otherwise mixing polylactide with other polyesters.
  • the degradable polymer comprises PLA which may be synthesized using any suitable methodology.
  • PLA may be synthesized either from lactic acid by a condensation reaction or by a ring-opening polymerization of a cyclic lactide monomer. Methodologies for the preparation of PLA are described in U.S. Pat. Nos.
  • the degradable polymer comprises a polyanhydride.
  • polyanhydrides suitable for use in the present disclosure include, but are not limited to, poly(adipic anhydride), poly(suberic anhydride), poly(sebacic anhydride), poly(dodecanedioic anhydride), poly(maleic anhydride), poly(benzoic anhydride), or combinations thereof.
  • the degradable polymer comprises polysaccharides, such as starches, cellulose, dextran, substituted or unsubstituted galactomannans, guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, heteropolysaccharides obtained by the fermentation of starch-derived sugar (e.g., xanthan gum), diutan, scleroglucan, derivatives thereof, or combinations thereof.
  • polysaccharides such as starches, cellulose, dextran, substituted or unsubstituted galactomannans, guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, heteropolysaccharides obtained by the fermentation of starch-derived sugar (e.g., xanthan gum), diutan, scleroglucan, derivatives thereof, or combinations thereof.
  • the degradable polymer comprises guar or a guar derivative.
  • guar derivatives suitable for use in the present disclosure include hydroxypropyl guar, carboxymethylhydroxypropyl guar, carboxymethyl guar, hydrophobically modified guars, guar-containing compounds, synthetic polymers, or combinations thereof.
  • the degradable polymer comprises cellulose or a cellulose derivative.
  • cellulose derivatives suitable for use in the present disclosure include cellulose ethers, carboxycelluloses, carboxyalkylhydroxyethyl celluloses, hydroxyethylcellulose, hydroxypropylcellulose, carboxymethylhydroxyethylcellulose, carboxymethylcellulose, or combinations thereof.
  • the degradable polymer comprises a starch.
  • starches suitable for use in the present disclosure include native starches, reclaimed starches, waxy starches, modified starches, pre-gelatinized starches, or combinations thereof.
  • the degradable polymer comprises acrylic-based polymers, such as acrylic acid polymers, acrylamide polymers, acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, polymethacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, ammonium and alkali metal salts thereof, or combinations thereof.
  • acrylic-based polymers such as acrylic acid polymers, acrylamide polymers, acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, polymethacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, ammonium and alkali metal salts thereof, or combinations thereof.
  • the degradable polymer comprises polyamides, such as polycaprolactam derivatives, poly-paraphenylene terephthalamide or combinations thereof.
  • the degradable polymer comprises nylon 6,6; nylon 6; KEVLAR, or combinations thereof.
  • the physical properties associated with the degradable polymer may depend upon several factors including, but not limited to, the composition of the repeating units, flexibility of the polymer chain, the presence or absence of polar groups, polymer molecular mass, the degree of branching, polymer crystallinity, polymer orientation, or the like.
  • a polymer having substantial short chain branching may exhibit reduced crystallinity while a polymer having substantial long chain branching may exhibit for example, a lower melt viscosity and impart, inter alia, elongational viscosity with tension-stiffening behavior.
  • the properties of the degradable polymer may be further tailored to meet some user and/or process designated goal using any suitable methodology such as blending and/or copolymerizing the degradable polymer with another polymer, or by changing the macromolecular architecture of the degradable polymer (e.g., hyper-branched polymers, star-shaped, or dendrimers, etc.).
  • any suitable methodology such as blending and/or copolymerizing the degradable polymer with another polymer, or by changing the macromolecular architecture of the degradable polymer (e.g., hyper-branched polymers, star-shaped, or dendrimers, etc.).
  • an operator may consider the degradation products that will result. For example, an operator may choose the degradable polymer such that the resulting degradation products do not adversely affect one or more other operations, treatment components, the formation, or combinations thereof. Additionally, the choice of degradable polymer may also depend, at least in part, upon the conditions of the well.
  • Nonlimiting examples of additional degradable polymers suitable for use in conjunction with the methods of this disclosure are described in more detail in U.S. Pat. Nos. 7,565,929 and 8,109,335, and U.S. Patent Publication Nos. 20100273685 A1, 20110005761 A1, 20110056684 A1 and 20110227254 A1, each of which is incorporated by reference herein in its entirety.
  • the degradable polymer further comprises a plasticizer.
  • the plasticizer may be present in an amount sufficient to provide one or more desired characteristics, for example, (a) more effective compatibilization of the melt blend components, (b) improved processing characteristics during the blending and processing steps, (c) control and/or regulation of the sensitivity and degradation of the polymer by moisture, (d) control and/or adjust one or more properties of the foam (e.g., strength, stiffness, etc.), or combinations thereof.
  • Plasticizers suitable for use in the present disclosure include, but are not limited to, derivatives of oligomeric lactic acid, such as those represented by the formula:
  • R and/or R′ are each a hydrogen, an alkyl group, an aryl group, an alkylaryl group, an acetyl group, a heteroatom, or combinations thereof provided that R and R′ cannot both be hydrogen and that both R and R′ are saturated;
  • q is an integer where the value of q ranges from greater than or equal to 2 to less than or equal to 75 or alternatively from greater than or equal to 2 to less than or equal to 10.
  • the term “derivatives of oligomeric lactic acid” may include derivatives of oligomeric lactide.
  • the plasticizer may be intimately incorporated within the degradable polymeric materials.
  • the DM comprises one or more components of BIOVERT NWB diverting agent, BIOVERT CF diverting agents, BIOVERT H150 diverter and fluid loss control material or combinations thereof.
  • BIOVERT NWB diverting agent is a near-wellbore biodegradable diverting agent; BIOVERT H150 diverter and fluid loss control material and BIOVERT CF is a complex fracture biodegradable diverting agent; each of which is commercially available from Halliburton Energy Services.
  • a DA may comprise a material suitable for placement in a wellbore formation concurrently with a DM that functions to enhance the rate of degradation of a DM.
  • the DM may be degraded via hydrolytic or aminolytic degradation in the presence of a DA.
  • the DA comprises an inorganic base, an organic base, an acid, a pH-modifying material precursor (e.g., base precursor, acid precursor), or combinations thereof.
  • the DA comprises a pH-modifying material precursor.
  • a pH-modifying material precursor e.g., base precursor, acid precursor
  • a pH-modifying material precursor is defined as a material or combination of materials that provides for delayed release of one or more acidic or basic species.
  • Such pH-modifying material precursors may also be referred to as time-delayed and/or time-released acids or bases.
  • the pH-modifying material precursors comprise a material or combination of materials that may react to generate and/or liberate an acid or a base after a period of time has elapsed. The liberation of the acidic or basic species from the pH-modifying material precursor may be accomplished through any means known to one of ordinary skill in the art with the benefits of this disclosure and compatible with the user-desired applications.
  • pH-modifying material precursors may be formed by modifying acids or bases via the addition of an operable functionality or substituent, physical encapsulation or packaging, or combinations thereof.
  • the operable functionality or substituent may be acted upon in any fashion (e.g., chemically, physically, thermally, etc.) and under any conditions compatible with the components of the process in order to release the acid or the base at a some user and/or process desired time and/or under desired conditions such as in situ wellbore conditions.
  • the pH-modifying material precursor may comprise at least one modified acid or base (e.g., having an operable functionality, encapsulation, packaging, etc.) such that when acted upon and/or in response to pre-defined conditions (e.g., in situ wellbore conditions such as temperature, pressure, chemical environment), an acid or base is released.
  • pre-defined conditions e.g., in situ wellbore conditions such as temperature, pressure, chemical environment
  • the pH-modifying material precursor may comprise an acidic or basic species that is released after exposure to an elevated temperature such as an elevated wellbore temperature (e.g., greater than about 120° F.).
  • the pH-modifying material precursor comprises a material which reacts with one or more components of the wellbore servicing fluid (e.g., reacts with an aqueous fluid present in the WSF) to liberate at least one acidic or basic species.
  • a pH-modifying material precursor as used herein generally refers to a component, which itself does not act as an acid or base by significantly modifying the pH of a solution into which it is introduced, but which, upon degradation, will yield one or more components capable of acting as an acid or a base by modifying the pH of that solution.
  • a pH-modifying material precursor may yield one or more components capable of modifying the pH of a solution by about 0.1 pH units, alternatively about 0.2 pH units, alternatively about 0.5 pH units, alternatively about 1.0 pH units, alternatively about 1.5 pH units, alternatively about 2.0 pH units, alternatively about 2.5 pH units, alternatively about 3.0 pH units, alternatively about 4.0 pH units, alternatively about 5.0 pH units, alternatively about 6.0 pH units, or alternatively about 7.0 or more pH units and such modifications may be an increase or decrease in pH.
  • the pH-modifying material precursor may be characterized as exhibiting a suitable delay time.
  • delay time refers to the period of time from when a pH-modifying material precursor, or a combination of pH-modifying material precursors, is introduced into an operational environment until the pH-modifying material precursor or combination of precursors begins to alter (e.g., begins to degrade) the DM, as will be disclosed herein.
  • the pH-modifying material precursor may exhibit an average delay time of at least about 1 hour, alternatively at least about 2 hours, alternatively at least about 4 hours, alternatively at least about 8 hours, alternatively at least about 12 hours, or alternatively at least about 24 hours.
  • the pH-modifying material precursor may be characterized as operable, as disclosed herein, within a suitable temperature range.
  • differing pH-modifying material precursors may exhibit varying temperature ranges of operability.
  • a pH-modifying material precursor, or combination of pH-modifying material precursors may be selected for inclusion in the SDDM such that the pH-modifying material precursor(s) exhibit a desired operable temperature range (e.g., an ambient downhole temperature for a given wellbore).
  • the degradation of the pH-modifying material precursor may be influenced by the temperature of the operational environment.
  • the rate of degradation of a given pH-modifying material precursor will be higher at higher temperatures.
  • the rate of degradation of a given pH-modifying material precursor may be generally higher when exposed to the environment within the wellbore.
  • the pH-modifying material precursor suitable for use in the present disclosure may exhibit an operable temperature range of from about 80° F. to about 400° F., alternatively from about 100° F. to about 300° F., or alternatively from about 120° F. to about 250° F.
  • the pH-modifying material precursor is an acid precursor.
  • the acid precursor comprises a reactive ester.
  • the reactive ester may be converted to an acidic species by hydrolysis of the ester linkage, for example by contact with water present in the WSF and/or water present in situ in the wellbore.
  • the acid precursor may comprise a lactone or lactide, a lactate ester, an acetate ester, a polyester, or combinations thereof.
  • the acid precursor comprises esters and/or polyesters of acids of the type described previously herein; esters and/or polyesters of polyols (e.g., glycerol, glycols) with acids of the type described previously herein; aliphatic polyesters; glucono-delta-lactone; glucoheptonic lactone; poly( ⁇ -caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; poly(amino acids); polyphosphazenes; poly(ortho esters); orthoesters (which may also be known as “poly ortho esters” or “ortho esters; or combinations thereof.
  • esters and/or polyesters of acids of the type described previously herein esters and/or polyesters of polyols (e.g., glycerol, glycols) with acids of the type described previously herein; aliphatic polyesters; glucono-delta-lactone; glucoheptonic lactone; poly
  • Nonlimiting examples of acid precursors suitable for use in the present disclosure include monoethylene monoformate, monoethylene diformate, ethylene glycol monoformate, ethylene glycol diformate, diethylene glycol monoformate, diethylene glycol diformate, triethylene glycol diformate, glyceryl monoformate, glyceryl diformate, glyceryl triformate; formate esters of pentaerythritol, tri-n-propyl orthoformate, tri-n-butyl orthoformate, methyl lactate, ethyl lactate, propyl lactate, butyl lactate, trilactin, polylactic acid, poly(lactides), methyl acetate, ethyl acetate, propyl acetate, butyl acetate, monoacetin, diacetin, triacetin, glyceryl diacetate, glyceryl triacetate, tripropionin (a triester of propionic acid and glycerol),
  • the DA comprises an acid.
  • acids suitable for use in the present disclosure include formic acid; acetic acid; lactic acid; glycolic acid; oxalic acid; propionic acid; butyric acid; monochloroacetic acid; dichloroacetic acid; trichloroacetic acid; hydrochloric acid; nitric acid; sulphuric acid; sulphonic acid; sulphinic acid; phosphoric acid; phosphorous acid; phosphonic acid; phosphinic acid; sulphamic acid; p-toluenesulfonic acid; or combinations thereof.
  • the DA comprises an inorganic base (e.g., bases, basic salts).
  • inorganic bases suitable for use in this disclosure include sodium hydroxide, potassium hydroxide, magnesium hydroxide, ammonium hydroxide, calcium carbonate, sodium carbonate, sodium bicarbonate, magnesium oxide, or combinations thereof.
  • the DA comprises an organic base.
  • the organic base comprises amines, ethylene diamine, alkanolamines, ethanolamine, thriethanolamine, secondary amines, tertiary amines, oligomers of aziridine, triethylene tetramine, tetraethylene pentamine, polyethyleneimine, or combinations thereof.
  • bases suitable for use as DAs in this disclosure are described in more detail in U.S. Patent Publication No. 2010/0273685 A1 and U.S. patent application Ser. No. 13/660,740 filed Oct. 25, 2012 and entitled “Wellbore Servicing Methods and Compositions Comprising Degradable Polymers,” each of which is incorporated by reference herein in its entirety.
  • the DM and the DA are each present in the SDDM in amounts effective to perform its intended function.
  • the amount of DM may range from about 10 wt. % to about 99 wt. %, alternatively from about 20 wt. % to about 80 wt. %, or alternatively from about 40 wt. % to about 70 wt. %, based on the total mass of the SDDM
  • the amount of DA may range from about 1 wt. % to about 80 wt. %, alternatively from about 10 wt. % to about 60 wt. %, or alternatively from about 20 wt. % to about 50 wt. %, based on the total mass of SDDM.
  • a DM of the type disclosed herein is associated with a DA of the type disclosed herein using any suitable methodology to form an SDDM.
  • the SDDM is prepared by contacting the DM with the DA, and thoroughly mixing the components for example by compounding, injection molding, extrusion molding, extrusion, melt extrusion, compression molding, or any suitable combination of these methods.
  • the DM is plasticized or melted by heating in an extruder and is contacted and mixed thoroughly with a DA of the type disclosed herein at a temperature of about greater than the melt temperature of the DM, the DA, or both.
  • the DM may be contacted with the DA prior to introduction of the mixture to the extruder (e.g., via bulk mixing), during the introduction of the DM to an extruder, or combinations thereof.
  • the SDDMs of this disclosure may be converted to SDDM particles by any suitable method (e.g., chipping, cutting, milling, grinding, etc.)
  • the SDDM particles may be produced about concurrently with the assembling of the SDDMs (e.g., on a sequential, integrated process line) or may be produced subsequent to the assembling of the SDDMs (e.g., on a separate process line such as an end use compounding and/or thermoforming line).
  • the SDDM is assembled via extrusion as previously described herein and the molten SDDM is fed to a shaping process (e.g., mold, die, lay down bar, etc.) where the SDDM is shaped.
  • the assembling of the SDDM (e.g., contacting/mixing of the DM and DA) may occur prior to, during, or subsequent to the shaping.
  • the SDDMs are further processed by mechanically sizing, cutting, or chopping the SDDM into particles using any suitable methodologies for such processes.
  • the SDDMs suitable for use in this disclosure comprise SDDM particles of any suitable geometry, including without limitation beads, hollow beads, spheres, ovals, fibers, rods, pellets, platelets, disks, plates, ribbons, and the like, or combinations thereof.
  • the SDDM comprises particles having an average particle size ranging from about 0.1 micron to about 3000 microns, alternatively from about 5 microns to about 2000 microns, alternatively from about 1 micron to about 500 microns, or alternatively from about 10 microns to about 100 microns.
  • the average particle size of the SDDM may be determined using any suitable methodology or instrumentation such as a Malvern particle size analyzer.
  • the DM comprises BIOVERT NWB diverting agent and the DA comprises sodium bicarbonate.
  • FIG. 1B displays a schematic of an SDDM particle 30 .
  • the SDDM 30 may be formed by contacting a DM 15 (e.g., a continuous phase) and a DA 40 (e.g., a discontinuous phase such as particles) both of the type disclosed herein, and compounding the components together into SDDM particles 30 having an average size of from about 50 microns to about 2000 microns.
  • the DM comprises BIOVERT CF diverting agent and the DA comprises encapsulated sodium hydroxide.
  • the SDDM in FIG. 1B may be formed by contacting the DM 15 and the DA 40 , and subjecting the mixture to the process of injection molding.
  • the SDDM may be further mechanically sized into SDDM particles 30 having an average size of from about 5 microns to about 200 microns by using any suitable methodology (e.g., cutting, chopping, and the like).
  • An SDDM of the type disclosed herein may be included in any suitable wellbore servicing fluid.
  • a “servicing fluid” refers to a fluid used to drill, complete, work over, fracture, repair, or in any way prepare a wellbore for the recovery of materials residing in a subterranean formation penetrated by the wellbore.
  • wellbore servicing fluids include, but are not limited to, cement slurries, drilling fluids or muds, spacer fluids, lost circulation fluids, fracturing fluids, diverting fluids or completion fluids.
  • the servicing fluid is for use in a wellbore that penetrates a subterranean formation.
  • the SDDM may be present in a wellbore servicing fluid in an amount of from about 0.01 pounds per gallon (ppg) to about 6 ppg, alternatively from about 0.1 ppg to about 2 ppg, or alternatively from about 0.1 ppg to about 1 ppg.
  • the DM and the DA are manufactured and then contacted together at the well site, forming the SDDM as previously described herein.
  • the DM and the DA are manufactured and then contacted together either off-site or on-the-fly (e.g., in real time or on-location), forming the SDDM as previously described herein.
  • either the DM or the DA is preformed and the other one would be made on-the-fly, and the two materials would then be contacted together on-the-fly, forming the SDDM as previously described herein.
  • the DM, DA and/or SDDM may be transported to the well site.
  • the SDDM may be assembled and prepared as a slurry in the form of a liquid additive.
  • the SDDM and a wellbore servicing fluid may be blended until the SDDM particulates are distributed throughout the fluid.
  • the SDDM particulates and a wellbore servicing fluid may be blended using a blender, a mixer, a stirrer, a jet mixing system, or other suitable device.
  • a recirculation system keeps the SDDM particulates uniformly distributed throughout the wellbore servicing fluid (e.g., a concentrated solution or slurry).
  • a wellbore servicing fluid comprising an SDDM of the type disclosed herein (i.e., a diverting fluid) for use in a wellbore
  • the diverting fluid prepared at the wellsite or previously transported to and, if necessary, stored at the on-site location may be combined with the SDDM, additional water and optional other additives to form the diverting fluid.
  • additional diverting materials may be added to the diverting fluid on-the-fly along with the other components/additives.
  • the resulting diverting fluid may be pumped downhole where it may function as intended.
  • a concentrated SDDM liquid additive is mixed with additional water to form a diluted liquid additive, which is subsequently added to a diverting fluid.
  • the additional water may comprise fresh water, salt water such as an unsaturated aqueous salt solution or a saturated aqueous salt solution, or combinations thereof.
  • the liquid additive comprising the SDDM is injected into a delivery pump being used to supply the additional water to a diverting fluid composition. As such, the water used to carry the SDDM particulates and this additional water are both available to the diverting fluid such that the SDDM may be dispersed throughout the diverting fluid.
  • the SDDM prepared as a liquid additive is combined with a ready-to-use diverting fluid as the diverting fluid is being pumped into the wellbore.
  • the liquid additive may be injected into the suction of the pump.
  • the liquid additive can be added at a controlled rate to the diverting fluid (e.g., or a component thereof such as blending water) using a continuous metering system (CMS) unit.
  • CMS continuous metering system
  • the CMS unit can also be employed to control the rate at which the liquid additive is introduced to the diverting fluid or component thereof as well as the rate at which any other optional additives are introduced to the diverting fluid or component thereof.
  • the CMS unit can be used to achieve an accurate and precise ratio of water to SDDM concentration in the diverting fluid such that the properties of the diverting fluid (e.g., density, viscosity), are suitable for the downhole conditions of the wellbore.
  • concentrations of the components in the diverting fluid e.g., the SDDMs
  • concentrations can be adjusted to their desired amounts before delivering the composition into the wellbore. Those concentrations thus are not limited to the original design specification of the diverting fluid and can be varied to account for changes in the downhole conditions of the wellbore that may occur before the composition is actually pumped into the wellbore.
  • the wellbore servicing fluid comprises a composite treatment fluid.
  • composite treatment fluid generally refers to a treatment fluid comprising at least two component fluids.
  • the two or more component fluids may be delivered into the wellbore separately via different flowpaths (e.g., such as via a flowbore, a wellbore tubular and/or via an annular space between the wellbore tubular and a wellbore wall/casing) and substantially intermingled or mixed within the wellbore (e.g., in situ) so as to form the composite treatment fluid.
  • Composite treatment fluids are described in more detail in U.S. Patent Publication No. 2010/0044041 A1 which is incorporated by reference herein in its entirety.
  • the composite treatment fluid comprises a diverting fluid (e.g., a wellbore servicing fluid comprising an SDDM of the type disclosed herein).
  • the diverting fluid may be formed from a first component and a second component.
  • the first component may comprise a diverter-laden slurry (e.g., a concentrated diverter-laden slurry pumped via a tubular flowbore) and the second component may comprise a fluid with which the diverter-laden slurry may be mixed to yield the composite diverting fluid, that is, a diluent (e.g., an aqueous fluid, such as water pumped via an annulus).
  • the diverter-laden slurry comprises an SDDM-laden slurry.
  • the diverter-laden slurry (e.g., the first component) comprises a base fluid, and diverting materials (e.g., an SDDM of the type disclosed herein).
  • the base fluid may comprise a substantially aqueous fluid.
  • substantially aqueous fluid may refer to a fluid comprising less than about 25% by weight of a non-aqueous component, alternatively less than about 20% by weight, alternatively less than about 15% by weight, alternatively less than about 10% by weight, alternatively less than about 5% by weight, alternatively less than about 2.5% by weight, alternatively less than about 1.0% by weight of a non-aqueous component.
  • aqueous fluids include, but are not limited to, water that is potable or non-potable, untreated water, partially treated water, treated water, produced water, city water, well-water, surface water, or combinations thereof.
  • the base fluid may comprise an aqueous gel, a viscoelastic surfactant gel, an oil gel, a foamed gel, an emulsion, an inverse emulsion, or combinations thereof.
  • the diluent may comprise a suitable aqueous fluid, aqueous gel, viscoelastic surfactant gel, oil gel, a foamed gel, emulsion, inverse emulsion, or combinations thereof.
  • the diluent may comprise one or more of the compositions disclosed above with reference to the base fluid.
  • the diluent may have a composition substantially similar to that of the base fluid; alternatively, the diluent may have a composition different from that of the base fluid.
  • the size and/or shape of the diverting material may be chosen so as to provide a plug (e.g., filter cake) within a given flowpath (e.g., within a point of entry into the wellbore and/or at a given distance from the wellbore within a fracture) having a given size, shape, and/or orientation.
  • the SDDM may be added to the wellbore servicing fluid to generate a diverting fluid which is then pumped downhole at the same time with additional diverting material.
  • the SDDM once placed downhole enters the formation and forms a diverter plug resulting in an increased pressure in the near wellbore region ranging from about 50 psi to about 5000 psi.
  • the SDDM may be configured, for example, via selection of a given size and/or shape, for placement at a given position (e.g., at a given depth of the wellbore) within such a flowpath.
  • the SDDM may be selected so as to have a multimodal particle size distribution for example, the DM (e.g., BIOVERT NWB diverting agent) may have about 20-25% of the material at a particle size of about 4 to about 10 mesh; about 50% of the material may have a particle size in the range of about 20 to about 40 mesh size while the remaining material may have a particle size of less than about 40 mesh.
  • mesh size is used to refer to the sizing of a particular screen as defined by as “ASTM E-11 Specifications” or “ISO 3310-1”.
  • mesh size may refer approximately to the greatest size of material that will pass through a particular mesh size, for example, the nominal opening.
  • the mesh size may also refer to the inside dimension of each opening in the mesh (e.g., the inside diameter of each square).
  • the SDDM may be selected so as to have a smaller particle size (e.g., smaller than about 100 mesh).
  • the near-wellbore region delimitation is dependent upon the formation where the wellbore is located, and is based on the wellbore surrounding conditions.
  • the far-wellbore region is different from the near-wellbore region in that it is subjected to an entirely different set of conditions and/or stimuli.
  • the near-wellbore and far-wellbore regions are based on the fracture length propagating away from the wellbore.
  • the near-wellbore region refers to about the first 20% of the fracture length propagating away from the wellbore (e.g., 50 feet) whereas the far-wellbore region refers to a length that is greater than about 20% of the fracture length propagating away from the wellbore (e.g., greater than about 50 feet).
  • smaller diverter particles may be carried a greater distance into the formation (e.g., into an existing and/or extending fracture).
  • a method of servicing a wellbore may comprise placing a wellbore servicing fluid (e.g., fracturing or other stimulation fluid such as an acidizing fluid) into a portion of a wellbore.
  • a wellbore servicing fluid e.g., fracturing or other stimulation fluid such as an acidizing fluid
  • the fracturing or stimulation fluid may enter flow paths and perform its intended function of increasing the production of a desired resource from that portion of the wellbore.
  • the level of production from the portion of the wellbore that has been stimulated may taper off over time such that stimulation of a different portion of the well is desirable.
  • previously formed flowpaths may need to be temporarily plugged in order to fracture or stimulate additional/alternative intervals or zones during a given wellbore service or treatment.
  • a wellbore servicing fluid into the formation to perform an intended function (e.g., fracturing or stimulation) and, thereafter, diverting the wellbore servicing fluid to another flowpath into the formation and/or to a different location or depth within a given flowpath may be continued until some user and/or process goal is obtained.
  • this diverting procedure may be repeated with respect to each of a second, third, fourth, fifth, sixth, or more, treatment stages, for example, as disclosed herein with respect to the first treatment stage.
  • the wellbore service being performed is a fracturing operation, wherein a fracturing fluid is placed (e.g., pumped downhole) at a first location in the formation and an SDDM is employed to divert the fracturing fluid from the first location to a second location in the formation such that fracturing can be carried out at a plurality of locations.
  • the SDDM may be placed into the first (or any subsequent location) via pumping a slug of a diverter fluid (e.g., a fluid having a different composition than the fracturing fluid) containing the SDDM and/or by adding the SDDM directly to the fracturing fluid, for example to create a slug of fracturing fluid comprising the SDDM.
  • the SDDM may form a diverter plug at the first location (and any subsequent location so treated) such that the fracturing fluid may be selectively placed at one or more additional locations, for example during a multi-stage fracturing operation.
  • the wellbore and/or the subterranean formation may be prepared for production, for example, production of a hydrocarbon, therefrom.
  • a diverting fluid e.g., a wellbore servicing fluid comprising an SDDM
  • preparing the wellbore and/or formation for production may comprise removing an SDDM (which has formed a temporary plug) from one or more flowpaths, for example, by allowing the diverting materials therein to degrade and subsequently recovering hydrocarbons from the formation via the wellbore.
  • SDDM which has formed a temporary plug
  • the SDDM comprises a degradable polymer of the type previously disclosed herein, which degrades due to, inter alia, a chemical and/or radical process such as hydrolysis or oxidation.
  • a chemical and/or radical process such as hydrolysis or oxidation.
  • the degradability of a polymer may depend at least in part on its backbone structure.
  • the presence of hydrolyzable and/or oxidizable linkages within the backbone structure may yield a material that will degrade as described herein.
  • the rates at which such polymers degrade may be at least partially dependent upon polymer characteristics such as the type of repetitive unit, composition, sequence, length, molecular geometry, molecular weight, morphology (e.g., crystallinity, size of spherulites, and orientation), hydrophilicity, hydrophobicity, surface area, and type of additives.
  • polymer characteristics such as the type of repetitive unit, composition, sequence, length, molecular geometry, molecular weight, morphology (e.g., crystallinity, size of spherulites, and orientation), hydrophilicity, hydrophobicity, surface area, and type of additives.
  • the ambient downhole environment to which a given polymer is subjected may also influence how it degrades, (e.g., temperature, presence of moisture, oxygen, microorganisms, enzymes, pH, pressure, the like, and combinations thereof).
  • the SDDM is of the type depicted in FIG. 1B .
  • SDDM particle 30 comprises a DM 15 and a DA 40 .
  • the DA 40 may accelerate degradation of the DM.
  • an encapsulated DA may have the structural integrity of the encapsulating material compromised (e.g., by in situ wellbore temperatures) such that the DA is contacted with the DM and begins to degrade the DM.
  • the DA which is in contact with the DM when placed in the wellbore under ambient surface conditions may degrade the DM at some rate (x) which is accelerated to a rate (y) when subjected to in situ wellbore conditions (e.g., elevated temperatures and/or pressures).
  • the DA (with or without encapsulation) which has been mixed with the DM is located at discrete locations within the DM such that SDDM can be envisioned as a composite material having a continuous phase of DM and a discontinuous phase of DA.
  • DA disposed within the DM may degrade DM molecules resulting in the formation of voids within the SDDM.
  • the resultant degraded SDDM particle 35 may be characterized by the appearance of voids/pores 60 (i.e., a porous structure).
  • the degraded SDDM particle 35 has a greater surface area exposed to the wellbore servicing fluid due to the presence of the pores 60 , when compared to the surface area of the original, undegraded SDDM particle 30 .
  • Degradation 70 of the diverter material 15 may be faster due to both the altered pH 55 and the increased surface area of the degraded SDDM particle 35 , when compared to the degradation 20 of diverter particles 10 comprising the same DM 15 , but lacking the pores as seen in FIG. 1A .
  • the degraded SDDM particle 35 comprises a degradable polymer having an enhanced surface area.
  • a reaction e.g., hydrolytic degradation
  • the shorter the reaction time frame will be for a fixed amount of material, while keeping all the other conditions unchanged (e.g., same pressure, same temperature, etc.).
  • porous diverter material of this disclosure obtained upon DA dissolution from polymer A that has the same mass x, may have a surface area of 2y, 5y, 10y, 20y, 50y, or 100y.
  • the porous diverter material may display faster degradation times than the original nonporous solid polymeric material A.
  • the SDDM may result in a degraded SDDM particle 35 which displays a surface area that is increased with respect to the solid diverter material (i.e., pore-free solid) by a factor of about 50, alternatively by a factor of about 100, or alternatively by a factor of about 200.
  • a mechanism of increasing the degradability of a DM may include physical alteration of the DM (e.g., induce pores to increase the surface area) as well as chemical and/or structural alterations such as cleaving the backbone of the DM, increasing the number of radicals present that attack the DM's polymer chains, catalyzing the decomposition reaction, etc.
  • the SDDM when subjected to degradation conditions of the type disclosed herein degrades in a time range of about 4 h, alternatively about 6 h, or alternatively about 12 h.
  • SDDMs of the type disclosed herein due to the presence of a DA substantially degrade in a time frame of less than about 1 week, alternatively less than about 2 days, or alternatively less than about 1 day.
  • the SDDM comprises a material which is characterized by the ability to be degraded at bottom hole temperatures (BHT) of less than about 120° F., alternatively less than about 250° F., or alternatively less than about 350° F.
  • BHT bottom hole temperatures
  • SDDMs of the type disclosed herein provide an economic advantage over the use of DMs as the SDDMs utilize a reduced amount of DM in comparison to provide a similar diverting capability.
  • a first embodiment which is a method of servicing a wellbore in a subterranean formation comprising placing a first wellbore servicing fluid comprising a self-degrading diverter material into the wellbore wherein the self-degrading diverter materials comprises (i) a diverting material and (ii) a degradation accelerator allowing the self-degrading diverter material to form a diverter plug at a first location in the wellbore or subterranean formation; diverting the flow of a second wellbore servicing fluid to a second location in the wellbore or subterranean formation; and removing the diverter plug, wherein the first and second wellbore servicing fluids may be the same or different.
  • a second embodiment which is the method of the first embodiment wherein the diverting material comprises a degradable material.
  • a third embodiment which is the method of the second embodiment wherein the degradable material comprises a degradable polymer.
  • a fourth embodiment which is the method of the third embodiment wherein the degradable polymer comprises polysaccharides; lignosulfonates; chitins; chitosans; proteins; proteinous materials; fatty alcohols; fatty esters; fatty acid salts; aliphatic polyesters; poly(lactides); poly(glycolides); poly( ⁇ -caprolactones); polyoxymethylene; polyurethanes; poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; polyvinyl polymers; acrylic-based polymers; poly(amino acids); poly(aspartic acid); poly(alkylene oxides); poly(ethylene oxides); polyphosphazenes; poly(orthoesters); poly(hydroxy ester ethers); polyether esters; polyester amides; polyamides; polyhydroxyalkanoates; polyethyleneterephthalates; polybutyleneterephthalates; polyethylenenaphthalenates, or combinations thereof.
  • n is an integer ranging from about 75 to about 10,000 and R comprises hydrogen, an alkyl group, an aryl group, alkylaryl groups, acetyl groups, heteroatoms, or combinations thereof.
  • a sixth embodiment which is the method of any of the second through third embodiments wherein the degradable polymer comprises polylactic acid.
  • a seventh embodiment which is the method of any of the first through sixth embodiments wherein the degradation accelerator comprises an inorganic base, an organic base, a base precursor, an acid, acid precursor, or combinations thereof.
  • An eighth embodiment which is the method of the seventh embodiment wherein the inorganic base comprises sodium hydroxide, potassium hydroxide, magnesium hydroxide, ammonium hydroxide, calcium carbonate, sodium carbonate, sodium bicarbonate, magnesium oxide, or combinations thereof.
  • a ninth embodiment which is the method of the seventh embodiment wherein the organic base comprises amines, ethylene diamine, alkanolamines, ethanolamine, thriethanolamine, secondary amines, tertiary amines, oligomers of aziridine, triethylene tetramine, tetraethylene pentamine, polyethyleneimine, or combinations thereof.
  • a tenth embodiment which is the method of the seventh embodiment wherein the acid comprises formic acid; acetic acid; lactic acid; glycolic acid; oxalic acid; propionic acid; butyric acid; monochloroacetic acid; dichloroacetic acid; trichloroacetic acid; hydrochloric acid; nitric acid; sulphuric acid; sulphonic acid; sulphinic acid; phosphoric acid; phosphorous acid; phosphonic acid; phosphinic acid; sulphamic acid; p-toluenesulfonic acid; or combinations thereof.
  • An eleventh embodiment which is the method of the seventh embodiment wherein the acid precursor comprises aliphatic polyesters; glucono-delta-lactone; glucoheptonic lactone; poly( ⁇ -caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; poly(amino acids); polyphosphazenes; poly(ortho esters); orthoesters; monoethylene monoformate, monoethylene diformate, ethylene glycol monoformate, ethylene glycol diformate, diethylene glycol monoformate, diethylene glycol diformate, triethylene glycol diformate, glyceryl monoformate, glyceryl diformate, glyceryl triformate; formate esters of pentaerythritol, tri-n-propyl orthoformate, tri-n-butyl orthoformate, methyl lactate, ethyl lactate, propyl lactate, butyl lactate, trilactin, polylactic acid,
  • a twelfth embodiment which is the method of any of the first through eleventh embodiments wherein the degradation accelerator is encapsulated.
  • a thirteenth embodiment which is the method of any of the first through twelfth embodiments wherein the self-degrading diverter material is present in the wellbore servicing fluid in an amount of from about 0.01 ppg to about 6 ppg.
  • a fourteenth embodiment which is the method of any of the first through thirteenth embodiments wherein the first wellbore servicing fluid comprises a diverting fluid and the second wellbore servicing fluid comprises a fracturing fluid.
  • a fifteenth embodiment which is the method of the fourteenth embodiment wherein a first portion of the fracturing fluid is placed into the formation at the first location before the diverter fluid is placed in the formation at the first location and a second portion of the fracturing fluid is diverted from the first location to the second location.
  • a sixteenth embodiment which is the method of any of the first through fourteenth embodiments wherein the self-degrading diverter materials has a particle size of from about 0.1 microns to about 3000 microns.
  • a seventeenth embodiment which is a wellbore servicing fluid comprising self-degrading diverter material wherein the self-degrading diverter material comprises polylactide, sodium carbonate and a carrier fluid.
  • An eighteenth embodiment which is the method of the seventeenth embodiment wherein the wellbore servicing fluid comprises a diverting fluid.
  • a nineteenth embodiment which is a method of servicing a wellbore in a subterranean formation comprising placing a wellbore servicing fluid into the subterranean formation at a first location; plugging the first location with a self-degrading diverter material comprising a diverting material and a degradation accelerator such that all or a portion of the wellbore servicing fluid is diverted to a second location in the subterranean formation; placing the wellbore servicing fluid into the subterranean formation at the second location; and allowing the self-degrading diverter material to degrade to provide a flowpath from the subterranean formation to the wellbore for recovery of resources from the subterranean formation.
  • a twentieth embodiment which is the method of the nineteenth embodiment wherein the wellbore servicing fluid is a fracturing fluid and the subterranean formation is fractured thereby at the first and second locations.
  • R L lower limit
  • R U upper limit
  • any number falling within the range is specifically disclosed.
  • R R L +k*(R U ⁇ R L ), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent.
  • any numerical range defined by two R numbers as defined in the above is also specifically disclosed.

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US11286413B2 (en) 2015-12-18 2022-03-29 Halliburton Energy Services, Inc. Modified biopolymers for diversion, conformance, and fluid loss control
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US11248167B2 (en) * 2016-06-30 2022-02-15 Halliburton Energy Services, Inc. Acid diversion in naturally fractured formations
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